Production of hydrocarbons (oil and/or gas) from subsea oil/gas wells typically involves positioning several items of production equipment, e.g., Christmas trees, manifolds, pipelines, flowline, skids, pipeline end terminations (PLETs), etc. on the sea floor. Flowlines or jumpers are normally coupled to these various items of equipment so as to allow the produced hydrocarbons to flow between and among such production equipment with the ultimate objective being to get the produced hydrocarbon fluids to a desired end-point, e.g., a surface vessel or structure, an on-shore storage facility or pipeline, etc. Jumpers may be used to connect the individual wellheads to a central manifold. In other cases, relatively flexible lines may be employed to connect some of the subsea equipment items to one another. The generic term “flowline” will be used throughout this application and in the attached claims to refer to any type of line through which hydrocarbon-containing fluids can be produced from a subsea well. As noted above, such flowlines may be rigid, e.g., steel pipe, or they may be somewhat flexible (in a relative sense as compared to steel pipe), e.g., flexible hose.
One challenge facing offshore oil and gas operations involves insuring the flowlines and fluid flow paths within subsea equipment remain open so that production fluid may continue to be produced. The produced hydrocarbon fluids will typically comprise a mixture of crude oil, water, light hydrocarbon gases (such as methane), and other gases such as hydrogen sulfide and carbon dioxide. In some instances, solid materials or debris, such as sand, small rocks, pipe scale or rust, etc., may be mixed with the production fluid as it leaves the well. The same challenge applies to other subsea flowlines and fluid flow paths used for activities related to the production of hydrocarbons. These other flowlines and flow paths could be used to, for example, service the subsea production system (service lines), for injecting water, gas or other mixture of fluids into subsea wells (injection lines) or for transporting other fluids, including control fluids (control lines).
One problem that is sometimes encountered in the production of hydrocarbon fluids from subsea wells is that a blockage may form in a subsea flowline or in a piece of subsea equipment. In some cases the blockage can completely block the flowline/equipment while in other cases the blockage may only partially block the flowline/equipment. For example, the solid materials entrained in the produced fluids may be deposited during temporary production shut-downs, and the entrained debris may settle so as to form all or part of a blockage in a flowline or item of production equipment. Another problem that may be encountered is the formation of hydrate blockages in the flowlines and production equipment.
In general, hydrates may form under appropriate high pressure and low temperature conditions. As a general rule of thumb, hydrates may form at a pressure greater than about 0.47 MPa (about 1000 psi) and a temperature of less than about 21° C. (about 70° F.), although these numbers may vary depending upon the particular application and the composition of the production fluid. Subsea oil and gas wells that are located at water depths greater than a few hundred feet or located in cold weather environments, are typically exposed to water that is at a temperature of less than about 21° C. (about 70° F.) and, in some situations, the surrounding water may only be a few degrees above freezing. Although the produced hydrocarbon fluid is relatively hot as it initially leaves the wellhead, as it flows through the subsea production equipment and flowlines, the surrounding water will cool the produced fluid. More specifically, the produced hydrocarbon fluids will cool rapidly when the flow is interrupted for any length of time, such as by a temporary production shut-down. If the production fluid is allowed to cool to below the hydrate formation temperature for the production fluid and the pressure is above the hydrate formation pressure for the production fluid, hydrates may form in the produced fluid which, in turn, may ultimately form a blockage which may block the production fluid flow paths through the production flowlines and/or production equipment. Of course, the precise conditions for the formation of hydrates, e.g., the right combination of low temperature and high pressure is a function of, among other things, the gas-to-water composition in the production fluid which may vary from well to well. When such a blockage forms in a flowline or in a piece of production equipment, either a hydrate blockage or a debris blockage or a combination of both, it must be removed so that normal production activities may be resumed.
FIG. 1 simplistically depicts one illustrative prior art system and method for removal of such a blockage from subsea flowlines/equipment. In this example, permanent production equipment in form of an illustrative production tree 12, a manifold 15 and a PLET 17 are positioned on the sea floor 13 (e.g., mudline) of a body of water having a surface 11. In this example, a blockage 20 will be depicted as being formed in a flowline 16 between the manifold 15 and the PLET 17. The production fluid flows from the manifold 15 toward the PLET 17, as indicated by the arrow 18 in FIG. 1. As depicted, the blockage 20 has an upstream side 20A and a downstream side 20B. In general, the prior art method involves use of system that includes, among other things, a surface vessel 10, a flowline remediation skid (FRS) 22 positioned on the sea floor 13, an optional chemical storage tank 34, and a subsea hydraulic power unit 24 (SHPU) that is suspended from the vessel 10 by a line 24X. Electrical power and communications maybe provided to the SHPU 24 via the line 24X. In turn, the SHPU 24 may supply power, communication signals and/or pressurized hydraulic fluid to the flowline remediation skid 22 via one or more lines 26. Although not depicted in FIG. 1, the SHPU 24 may also supply power, communication signals and/or pressurized hydraulic fluid to the optional chemical storage tank 34 by another connection line (not shown)
In the example depicted in FIG. 1, the flowline remediation skid 22 is operatively coupled to the manifold 15 by a flexible remediation flow line 28 at connection point 28X, an access point that is upstream of the blockage 20. In other examples, the flowline remediation skid 22 may be operatively coupled to equipment or lines even further upstream of the blockage 20, e.g., the tree 12, or to an access point in the flowline 16 itself (although neither of these situations is depicted in FIG. 1). In some cases, the flowline remediation skid 22 may be operatively coupled to an access point, such as the PLET 17, that is positioned downstream of the blockage 20, as depicted by the dashed-line remediation flow line 28A. The connection 28X between line 28 and the manifold 15 may be a so-called stab-in connection that is commonly employed in subsea equipment to facilitate the connection of a flowline to an item of subsea equipment by use of an ROV. The chemical storage tank 24 (if used) is operatively coupled to the flowline remediation skid 22 by a flexible remediation flow line 36.
The flowline remediation skid 22 is operatively coupled to a plurality of risers 30A-B (e.g., coiled tubing, hose, drill pipe, etc.) that extend from the vessel 10 by a plurality of flexible remediation flow lines 32A-B, respectively. The risers 30A-30B are both adapted to receive lighter fluids and gases (as depicted by the arrows 31) from the outlet of the flowline remediation skid 22, as described more fully below. The term “remediation flow lines” is used throughout this application to indicate that lines 28, 32A-B and 36 are not part of the normal production flowlines used in producing hydrocarbons from the well. Also depicted in FIG. 1 is an illustrative ROV (Remotely Operated Vehicle) 38 that is operatively coupled to the vessel 10 by a simplistically depicted ROV umbilical 40. The ROV 38 is used for, among other things, connecting the various lines 26, 28, 32A-B and 36 among the subsea remediation equipment, e.g., the flowline remediation skid 22, the chemical storage tank 34 (when used) and the SHPU 24, and to observe remediation operations.
As shown in FIG. 2, the flowline remediation skid 22 typically includes a simplistically depicted sump/separator pressure vessel 23. The vessel 23 comprises an upper portion 23A and a sump 23B. The vessel 23 has a process fluid inlet 25 that is adapted to receive production fluid from the manifold 15 and the remnants of the blockage 20 as it is removed. The vessel 23 also comprises first and second process fluid outlets 27A-B whereby relatively lighter fluids and gas (as depicted by the arrows 31) are pumped up the risers 30A-B, respectively, using one or more pumps (not shown) that are part of the flowline remediation skid 22. The sump 23B comprises an outlet 29 whereby solid materials that collect in the sump 23B, e.g., debris and/or portions of the blockage 20, may be removed from the sump 23B when the flowline remediation skid 22 is retrieved to the vessel 10 periodically or after remediation processes are completed. The upper portion 23A of the pressure vessel 23 is sized and designed such that it has sufficient volume to allow for sufficient residence time of the production fluid received into the vessel 23 so that substantially all or a significant portion of the entrained solids (e.g., blockage remnants and/or solids) in the production fluid to fall into the sump 23B. By way of example only, the vessel 23 may be relatively large, e.g., a diameter of about 0.6-1.2 meters (about 2-4 feet) and a length of about 2.4-3 meters (about 8-10 feet) with an internal capacity of about 3.8 m3 about 1000 gallons) or greater. If employed, the chemical storage tank 34 is used to store chemicals, e.g., methanol or other suitable hydrate formation inhibitors, which may be employed in the blockage removal process.
Several techniques have been employed to remove blockages (debris and/or hydrates) from subsea flowlines and subsea production equipment. In the example depicted in FIG. 1, wherein the flowline remediation skid 22 is operatively coupled to the manifold 17, the method may involve first injecting chemicals into an area on the upstream side 20A of the blockage 20 in an attempt to chemically dissolve or soften the blockage 20. Thereafter, efforts are undertaken to reduce the pressure on the upstream side 20A of the blockage 20 by creating a region of relatively low pressure on the upstream side 20A of the blockage 20. The area of low pressure serves at least two purposes. First, by exposing the blockage 20, in this case a hydrate blockage, to a lower pressure on its upstream side 20A that is less than the hydrate formation pressure, all or a part of the blockage 20 may essentially “melt” away (via sublimation). Second, the pressure on the upstream side 20A of the blockage 20 may be reduced in an attempt to create a differential pressure across the blockage 20 (with higher pressure being present on the downstream side 20B of the blockage) so as to force the blockage 20 through the manifold 15 and into the separator/sump vessel 23 on the flowline remediation skid 22. One illustrative prior art method to create this region of low pressure on the upstream side 20A of the blockage 20 is as follows. When the flowline remediation skid 22 is initially lowered to the sea floor 13, the internal pressure within separator/sump vessel 23 may be maintained at a relatively low pressure, e.g., about 0.101 MPA (about 1 atmosphere). At some point after the flowline remediation skid 22 is positioned on the sea floor 13 and coupled to the manifold 15, appropriate valves are actuated such that fluid communication is established between the flowline 16 on the upstream side 20A of the blockage 20 and the separator/sump vessel 23 thereby reducing the pressure in the flowline 16. Once the production fluid, with portions of the removed blockage 20 entrained therein, is introduced into the pressure vessel 23 (via inlet 25—see FIG. 2), substantially all or a significant portion of the entrained solids (e.g., blockage remnants and/or solids) in the production fluid collect and fall into the sump 23B.
One problem with the above prior art system is that, in deep water applications, the density of the production fluid and the resulting back pressure (due to the hydrostatic head) in the lines 30A-30B limit or prevent the ability to reduce pressure in the flowline 16 on the upstream side 20A of the blockage 20 to a sufficiently low level. As a result, it may be difficult to create a low enough pressure region on the upstream side 20A of the blockage 20 such that hydrate sublimation occurs, i.e., it may be difficult to establish a pressure on the upstream side 20A of the blockage 20 that is less than the hydrate formation pressure. Additionally, due to the back pressure (the hydrostatic head in the lines 30A-B) it may not be possible to create enough of a differential pressure across then blockage 20 so as to dislodge or break-up the blockage 20 and force it into the vessel 23 on the flowline remediation skid (FRS) 22
The effectiveness of this prior art method may be limited by several other factors. First, the volume capacity of the pressure vessel 23 may be limited by the depth of the water since the vessel 23 must be designed so as to resist the external pressure on the vessel 23 from the water. All other things being equal, larger diameter vessels 23 are more likely to collapse under external pressure than are small diameter vessels. Accordingly, in applications where the vessel 23 needs a larger capacity, it must be manufactured with thicker walls and/or stiffeners so as to withstand the external pressure of the surrounding water, all of which tend to make it heavier as well as more expensive to manufacture and transport to the offshore well site. Moreover, such a larger pressure vessel 23 may require a surface vessel 10 with enhanced lifting capabilities due to the size and weight of the vessel 23, all of which tend to add to the cost of installing and retrieving the vessel 23 from the sea floor. This is especially true when a larger sump 23B on such a larger vessel 23 is filled with solid materials due to the remediation process. Yet another problem with the prior art system described above is that it consumes significant amounts of valuable plot space on the sea floor 13, especially if the chemical storage tank 34 is employed. This increase in the required overall space on the sea floor 13 space to set the blockage remediation equipment can become problematic in that it may be difficult to position the blockage remediation equipment around the permanently installed subsea production equipment in tightly packed subsea field architectures or in areas where steep slopes are present on the sea floor 13 or geotechnical hazards are prevalent.
A major disadvantage with several prior art systems is that they include hydrate remediation equipment that is installed on the sea floor 13 during remediation operations. This requires that any connections between the surface vessel 10 and the subsea equipment must be rapidly disconnected in case of a loss of position (so called drive-off or drift-off) of the surface vessel 10; otherwise the equipment would be damaged. Additionally, such a situation could even represent a major risk to the integrity of the subsea production system if the equipment on the sea floor 13 is dragged around by the downlines (e.g., 30A, 30B) connected to the moving vessel 10.
The present application is directed to various systems, methods and devices useful in removing blockages, e.g., hydrate plugs, debris plugs, etc., from subsea flowlines and subsea equipment that may eliminate or at least minimize some of the problems noted above.